As part of the Synergetic Utilisation of CO (Formula presented.) storage Coupled with geothermal EnErgy Deployment project, investigating CO (Formula presented.) reinjection with different seismic methods, both passive and active seismic surveys have been conducted at the geothermal power plant at Hellisheiði, Iceland. During the 2021 survey, two geophone lines recorded noise for a week. We process the passive-source data with seismic interferometry to image the subsurface structure around the CarbFix2 reinjection reservoir. To improve image quality, we perform an illumination analysis to select only noise panels dominated by body-wave energy. The results show that most noise panels are dominated by air-wave energy arriving from the direction of the power plant. We use panels with a near-vertical incidence to create a zero-offset image and a larger selection of body-wave-dominated panels to create virtual common-shot gathers. We process the gathers with a simple reflection seismology processing workflow to obtain stacked images. The zero-offset images show a relatively lower signal-to-noise ratio and only horizontal reflectors. The stacked images show slightly dipping reflectors and possibly lateral amplitude variations around the expected injection region. This could indicate a region of interest for future research into the reinjection reservoir.

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The microscopic structure of low-permeability tight reservoirs is complicated due to diagenetic processes that impact the pore-fluid distribution and hydraulic properties of tight rocks. As part of an ongoing study of carbon dioxide-enhanced oil and gas recovery (CO2-EOR/EGR) and CO2 sequestration, this research article adopts an integrated approach to investigate the contribution of the micropore system in pore-fluid distribution in tight sandstones. A new dimensionless number, termed the microscopic confinement index (MCI), was established to select the right candidate for microscopic CO2 injection in tight formations. Storativity and containment indices were essential for MCI estimation. A set of experiments, including routine core analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR), was performed on three tight sandstone rock samples, namely Bandera, Kentucky, and Scioto. Results indicate that the presence of fibrous illite acting as pore bridging in Bandera and Kentucky sandstone samples reduced the micropore-throat proportion (MTMR), leading to a significant drop in the micropore system confinement in Kentucky and Bandera sandstone samples of 1.03 and 0.56, respectively. Pore-filling kaolinite booklets reduced the micropore storativity index (MSI) to 0.48 in Kentucky and 0.38 in Bandera. On the other hand, the absence of fibrous illite and kaolinite booklets in Scioto sandstone led to the highest micropore system capability of 1.44 MTMR and 0.5 MSI to store and confine fluids. Therefore, Scioto sandstone is the best candidate for CO2 injection and storage among the tested samples of 0.72 MCI.@en

Macro-, meso-, micro-pore systems combined with clay content are critical for fluid flow behavior in tight sandstone formations. This study investigates the impact of clay mineralogy on pore systems in tight rocks. Three outcrop samples were selected based on their comparative petrophysical parameters (Bandera, Kentucky, and Scioto). Our experiments carried out to study the impact of clay content on micro-pore systems in tight sandstone reservoirs involve the following techniques: Routine core analysis (RCA), to estimate the main petrophysical parameters such as porosity and permeability, X-ray diffraction (XRD), and scanning electron microscopy (SEM) to assess mineralogy and elemental composition, Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), and Micro-Computed Tomography (Micro-CT) to analyze pore size distributions. Clay structure results show the presence of booklets of kaolinite and platelets to filamentous shapes of illite. The Scioto sample exhibits a micro-pore system with an average pore body size of 12.6±0.6 μm and an average pore throat size of 0.25±0.19 μm. In Bandera and Kentucky samples illite shows pore-bridging clay filling with an average mineral size of around 0.25±0.03 μm, which reduces the micro-pore throat system sizes. In addition, pore-filling kaolinite minerals with a diameter of 5.1±0.21 μm, also reduce the micro-pore body sizes. This study qualifies and quantifies the relationship of clay content with primary petrophysical properties of three tight sandstones. The results help to advance procedures for planning oil recovery and CO₂ sequestration in tight sandstone reservoirs.

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As part of a seismic monitoring project in a geothermal field, where the feasibility of re-injection and storage of produced CO₂ is being investigated, a P- and S-wave seismic velocity characterisation study was carried out. The effect of axial and radial (up to 42 MPa) stress, pore pressure (up to 17 MPa), pore fluid (100% brine or supercritical CO₂) and temperature (21–100 °C) on seismic properties were studied in the laboratory for the two main reservoir formations at the Kızıldere geothermal reservoir. Each (un)confined compressive strength test performed revealed a similar trend: rapidly increasing velocity at low stresses followed by a more moderate increase at higher stresses. The data implied that the stress-dependency of the velocity increased with temperature. Increasing temperatures resulted in decreasing P-wave velocities due to mineral thermal expansion. This temperature-dependency increased with reducing stress levels. The S-wave velocity seems to be more sensitive to changes in pore pressure than the P-wave velocity. On the other hand, the S-wave velocity is less affected by an increasing axial stress compared to the P-wave velocity. By performing multiple nonlinear regression on the velocity dataset, related to a brine-saturated fractured marble, second-degree polynomial trends were found for the P- and S-wave velocity, as a function of temperature, axial stress, and pore pressure, that can potentially be used for predicting velocities at Kızıldere, or other similar, geothermal site(s). For distinguishing between a 100% brine-saturated versus a fully supercritical CO₂-saturated fracture, the arrival times of the first arrivals were too close to each other to allow their utilization. The fracture aperture was too small compared to the wavelength of the source signal. However, differences in P- and S-wave amplitudes of the first arrivals were seen, where the supercritical CO₂-saturated crack revealed consistently lower peak and trough amplitudes compared to the brine-saturated scenario.

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Carbon dioxide (CO₂) injection has been widely used in conventional reservoirs for enhanced oil recovery and CO₂ sequestration. Nevertheless, the effectiveness of CO₂ injection in tight reservoirs is limited due to diagenetic processes that impact displacement efficiency. This research work assesses the performance of CO₂ injection in tight reservoirs and evaluates oil mobilization and fluid distribution within the rock pore systems. A set of experiments, including routine core analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury injection capillary pressure (MICP), was performed on Scioto sandstone. Three core-flooding runs were conducted to evaluate oil recovery of different injection schemes, including tertiary miscible CO₂ injection, secondary immiscible CO₂ injection, and secondary miscible CO₂ injection. A nuclear magnetic resonance (NMR) spectrometer was utilized to evaluate the fluid distribution in pre- and postflooding schemes. Results show that secondary miscible CO₂ injection provided the highest displacement efficiency (E_d) of 88%, with oil mobilized from both micro- and macropore systems, leading to the highest oil recovery of 93% original oil in place (OOIP). Tertiary miscible CO₂ injection had E_d of 67%, providing an ultimate oil recovery of 79% OOIP mostly from the macropore system. Limited contribution of micropores during the tertiary miscible CO₂ injection is attributed to the increased water content as a result of previously conducted secondary water flooding. Secondary immiscible CO₂ injection showed the least oil recovery among the injection schemes of 68% OOIP, which is attributed to the unstable displacement, as indicated by E_d of 52%. The efficiency of pore fluid displacement was determined through NMR analyses, and the findings are in line with the displacement efficiency values obtained from core-flood experiments, with a strong positive correlation. This finding is a promising strategy for determining a suitable CO₂ injection scheme in tight rocks for oil recovery and CO₂ storage.

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A full petrographic and petrophysical characterization of tight sandstones has been conducted as part of ongoing study of Carbon Dioxide Enhanced Oil and Gas Recovery (CO₂-EOR/EGR) and CO₂sequestration. The main purpose of this study is to give novel perception into the interplay of the rock characteristics and fluid flow in tight formations, which are candidates for EOR/EGR processes (macroscopic sweep vs. microscopic displacement efficiency). To achieve this, several experimental techniques, including routine core analysis, X-ray diffraction (XRD), X-ray fluorescence (XRF), thin sections petrography, Scanning Electron Microscopy (SEM) and capillarity/pore size distributions by using Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), and Micro-Computed Tomography (Micro-CT), were conducted. Three tight sandstone rock samples (Bandera, Kentucky, and Scioto) were used in this work and particular attention was paid to the impact of clay content on rock's pore system and other petrophysical characteristics and hence fluids flow during production process. Results indicate that the presence of fibrous illite clay acting as pore bridging in Bandera and Kentucky samples have blocked the overall micro-pore system causing a significant reduction in the micro-pore throat system to 36% in Bandera sand and 50.9% in Kentucky sample. On the other hand, absence of fibrous illite and the presence of illite platelets in the Scioto sandstone led to a clear preservation of the sample's micro-pore throat attributing to a total of 59.1% of the total pore throat system. A new dimensionless number (dimensionless micro-pore throat modality) was established, defined as the ratio of micro-to macro-pore sizes. This shows that Scioto has the highest value of 1.44 implying that both macro- and micro-pore systems contribute to flow. Therefore, the mitigation of oil bypass from smaller pores should be a key criterion in selecting the proper recovery methods. Results show the effect of clay mineralogy on pore system considering a part of the physical and spatial properties the pore/grain framework of the tight sandstones.

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The main goal of the project is to create a comprehensive training platform that will be helpful in modifying and updating educational programs at universities related to the sub surface exploitation related industry, with the latest and practical knowledge linked to the effective application of circular economy waste management principles.@en

Foam is applied in enhanced oil recovery to improve the sweep of injected gas and increase oil recovery, by greatly reducing the mobility of gas. In the laboratory, X-ray computed tomography is commonly used to evaluate the performance of foam in core plugs. However, foam properties, such as bubble size and capillary pressure, are much more difficult to measure. In recent years, microfluidic models have gained much attention because they easily facilitate the imaging study of in-situ foam. However, it is still challenging to estimate capillary pressure, in a model with a uniform depth of etching. In this paper, we report a novel technique to estimate water saturation and capillary pressure of foam in two 1-meter-long model fractures. Both model fractures are made of glass plates. They have different roughness and hydraulic apertures. Unlike microfluidics with uniform depth of etching, our model fractures each has a variation of aperture. We characterize the roughness and represent the aperture distribution of the fracture as a network of pore bodies and pore throats. In this study, foam is pre-generated and then injected into the fractures. The inlet and outlet valves are closed for 24 hr after foam reaches steady-state. We use a high-speed camera to visualize foam in the fractures. We use ImageJ software to analyze foam texture and quantify bubble density, average bubble size and polydispersivity. In addition, we estimate water saturation and capillary pressure by analyzing images in terms of fracture geometry. We found that water in foam resides in locations of narrow aperture, Plateau borders, lamellae between bubbles, and water films on glass walls. Water-filled zones of narrow aperture and Plateau borders account for almost all the water. During the re-distribution of water and gas in static foam, in-flow and out-flow of water must take paths along the network of Plateau borders and water-occupied zones, as they are the only continuous paths for water flow. In both model fractures, the decrease in water saturation coincides with an increase in capillary pressure, as expected. This novel technique of estimation of water saturation and capillary pressure of foam provides insights for studies of foam in naturally fractured reservoirs with complex geometry, where measuring such foam properties is challenging. This analysis is possible because aperture varies along our model fractures, unlike most microfluidic devices. Our technique would also have an application to foam aquifer remediation and CO ₂ sequestration.

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In the ACT Consortium funded project SUCCEED, researchers study the potential for monitoring the process of (re-)injecting produced and captured CO2 into the Hellisheiði geothermal field for the aid of enhancing geothermal deployment as well as permanently storing CO2 through mineralization. The Hellisheiði site provides an excellent opportunity for demonstrating an innovative seismic monitoring technique. Prior to conducting an active-source monitoring survey, we perform acoustic transmission measurements, on Hellisheiði rock samples, at field-representative stress conditions to obtain the seismic-response characteristics of all present formations. Subsequently, we use the acquired velocity data as an input for simulating 2D seismic surveys using a subsurface model representing the Hellisheiði site. Results show that the impact of increasing depth, i.e., stress, on seismic velocities is most apparent for the porous basalt layers due to their relatively large portion of open pore space, allowing for substantial compaction, increasing their bulk density and thus velocity. The poorly-consolidated hyaloclastites reveal a negligible effect of increasing depth on their velocity as the material already reached its maximum compaction at low stresses, thus at shallow depths. Comparison of synthetic and field geophone data reveal that the velocity profiles have to be updated for the shallow depths in the model.@en

Producing geothermal heat from production water causes cooldown from the reservoir temperature up to 250C at fluid pressures from over 100 bar to 10 bar.During the process degassification of CO2 and methane cause reduction in pH and by that dissolution and precipitation of minerals.At depth, mineral precipitation in the reservoir restricts flow paths through the cyclic system, resulting into injectivity loss, by that higher injection pressures result in additional costs.Due the large number of timesteps,numerically modeling mineralization, accounting for the reaction kinetics, can be computationally expensive. These simulations are less expensive when assuming a local equilibrium between the reactants and reaction-products. As described in Meulenbroek et all. (2020) we present an analytical model for mineral precipitation in a low-enthalpy geothermal reservoir.The three different reaction regimes are (1) fast reactions (2) very slow reactions (3) reaction/transport intermediate zone.We focus on the near-wellbore region in the reservoir, where precipitation can behave as a ‘skin’ and has a more dramatic impact on the injectivity than precipitation further downstream. Our numerical model uses a coupling approach between PHREEQC and COMSOL utilizing the qualification of the different reaction regimes. This methodology was validated by using an analytical solution of a specific mineralization case. In addition it was compared to a field case. @en

This work is conducted within the framework of SUCCEED, a research consortium with the aim to validate the utilization of produced CO2, from the Hellisheiði geothermal plant in Iceland, for re-injection into the field for: i) pressure maintenance, and thus promoting geothermal production, and ii) permanent storage in basaltic formations through CO2 mineralisation. The objective of work carried out at Hellisheiði in SUCCEED is to provide a state-of-the-art, cost-effective, and low-environmental impact coupled geothermal-CO2 storage monitoring technique. In this work, a detailed seismic-velocity and mechanical behaviour-characterisation study was carried out on various rock formations present at the outcrops near the Hellisheiði geothermal site.Laboratory experiments include well-controlled active-source acoustic-assisted unconfined (UCS) and confined (CCS) compressive strength tests. Where the former, i.e., UCS, allow for investigating the mechanical behaviour, or static elastic properties, of the assessed rock formations, the latter, i.e., CCS, shed light on the seismic velocities at field-representative stress conditions (up to 70 MPa). The abovementioned experiments were conducted at ambient temperature and at dry pore-space conditions. For studying pore-scale phenomena (e.g., number of connected pores, mineralogy, etc.), several thin sections were prepared and micro computed tomography (micro-CT) scans were taken.The studied rock formations included basalts with varying porosities (ranging from 22 to 51 %), i.e., the main reservoir formation, hyaloclastites, and dykes. Micro-CT scan analyses, conducted on the basaltic reservoir formation in Hellisheiði, revealed that its pore structure is highly heterogeneous. Active-source acoustic-assisted UCS tests showed similar velocity - stress trends: a rapid increase in velocity at low stress levels, related to closure of potential microcracks (and thus compaction), followed by a more modest increase at higher levels of axial stress. The pyroclastic hyaloclastite appeared to be the weakest material assessed, revealing relatively low seismic velocities, a static Young modulus of 2.54±0.09 GPa, and an ultimate strength of around 4.3 MPa. On the contrary, the igneous intrusion, i.e., dyke, is by far the stiffest material studied, yielding a Young modulus of 34.85±0.39 GPa and an ultimate strength of more than 200 MPa. The investigated basalt samples indicated a porosity-dependent Young modulus and compressional-wave velocity, where both the modulus and velocity decrease significantly with increasing (connected) porosity following a power-law function.@en

By trapping gas, foam can improve the sweep efficiency in enhanced oil recovery. In this study, to understand gas trapping in fractures, we have conducted experiments in a model fracture with a hydraulic aperture of 80 μm. One wall of the fracture is rough, and the other wall is smooth. The fracture is made of two glass plates and the direct visualization of foam flow inside the fracture is facilitated using a high-speed camera. ImageJ has been used to perform image analysis and quantify the properties of the foam. We find that pre-generated foam has been further refined inside the model. Foam flow reaches local equilibrium, where the rate of bubble generation equals that of bubble destruction, within the model. Foam texture becomes finer and less gas is trapped as the interstitial velocity and pressure gradient increase. Shear-thinning rheology of foam has also been observed. The behavior of gas trapping in our model fracture is different from that in other geological porous media. The fraction of trapped gas is much lower (less than 7%). At the extreme, when velocity increases to 6.8 mm/s (pressure gradient to 1.8 bar/m), all the foam bubbles are flowing and there is no gas trapped inside the fracture.@en

As part of a seismic monitoring project in a geothermal field, where the feasibility of re-injection and storage of produced CO₂ is being investigated, a P-and S-wave seismic velocity characterisation study was carried out. The effect of axial (up to 95 MPa) and radial (up to 60 MPa) stress on the seismic velocity was studied in the laboratory for a broad range of dry sedimentary and metamorphic rocks that make up the Kızıldere geothermal system in Turkey. Thin section texture analyses conducted on the main reservoir formations, i.e., marble and calcschist, confirm the importance of the presence of fractures in the reservoir: 2D permeability increases roughly by a factor 10 when fractures are present. Controlled acoustic-assisted unconfined and confined compressive strength experiments revealed the stress-dependence of seismic velocities related to the several rock formations. For each test performed, a sharp increase in velocity was observed at relatively low absolute stress levels, as a result of the closure of microcracks, yielding an increased mineral-to-mineral contact area, thus velocity. A change in radial stress appeared to have a negligible impact on the resulting P-wave velocity, as long as it exceeds atmospheric pressure. The bulk of the rock formations studied showed reducing P-wave velocities as function of increasing temperature due to thermal expansion of the constituting minerals. This effect was most profound for the marble and calcschist samples investigated.

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In this study, to investigate how gravity affects foam in open vertical fractures, we report foam experiments in three 1-m-long, 15-cm-wide glass-model fractures. Each fracture has a smooth wall and a roughened wall. Between the two walls is a slit-like channel representing a single geological fracture. Three model fractures (Models A, B, and C) share the same roughness and have different hydraulic apertures of 78, 98, and 128 µm, respectively. We conduct foam experiments by horizontal injection in the three model fractures placed horizontally and sideways (i.e., with the model fractures turned on their long side), and in Model A placed vertically with injection upward or downward. Direct imaging of the foam inside the model fracture is facilitated using a high-speed camera. We find that foam reaches local equilibrium (LE; where the rate of bubble generation equals that of bubble destruction) in horizontal-flow experiments in all three model fractures and in vertical-flow experiments in Model A. In fractures with a larger hydraulic aperture, foam is coarser because of less in-situ foam generation. In the vertical-flow experiments in Model A, we find that the properties of the foam are different in upward and downward flow. Compared with downward flooding, upward flooding creates a finer-texture foam, as sections near the inlet of this experiment are in a wetter state, which benefits in-situ foam generation. Moreover, less gas is trapped during upward flooding, as gravitational potential helps overcome the capillarity and moves bubbles upward. In the sideways-flow experiments, gravity segregation takes place. As a result, drier foam propagates along the top of the fractures and wetter foam along the bottom. The segregation is more significant in fractures with a larger hydraulic aperture. At foam quality 0.8, gas saturation is 27.7\ and 19.3\0.8\ respectively. Despite the gravity segregation in all three model fractures, water and gas are not completely segregated. All three model fractures thus represent a capillary transition zone, with greater segregation with increasing aperture. Our results suggest that the propagation of foam in vertical natural fractures meters tall and tens of meters long, with an aperture of hundreds of microns or greater, is problematic. Gravity segregation in foam would weaken its capacity in the field to maintain uniform flow and divert gas in a tall fracture over large distances.@en

In enhanced oil recovery, foam can effectively mitigate conformance problems and maintain a stable displacement front, by trapping gas and reducing its relative permeability in situ. In this study, to understand gas trapping in fractures and how it affects foam behavior, we report foam experiments in a 1-m-long glass model fracture with a hydraulic aperture of 80 μm. One wall of the fracture is rough, and the other is smooth. Between the two is a 2D porous medium representing the aperture in a fracture. The fracture model allows direct visualization of foam inside the fracture using a high-speed camera. This study is part of a continuing program to determine how foam behaves as a function of the geometry of the fracture pore space (AlQuaimi and Rossen in Energy & Fuels 33: 68-80, 2018a). We find that local equilibrium of foam (where the rate of bubble generation equals that of bubble destruction) has been achieved within the 1-m model fracture. Foam texture becomes finer, and less gas is trapped as interstitial velocity, and pressure gradient increase. Shear-thinning rheology of foam has also been observed. The fraction of trapped gas is significantly lower in our model (less than 7%) than in 3D geological pore networks. At the extreme, when velocity increases to 7 mm/s, there is no gas trapped inside the fracture. Our experimental results of trapped-gas fraction correlate well with the correlation of AlQuaimi and Rossen (SPE J 23: 788-802, 2018b) for fracture-like porous media. This suggests that the correlation can also be applied to gas trapping in fractures with other geometries.@en

Foam coarsening by diffusion (Ostwald ripening) has been well studied in bulk foams. However, it is less well understood in porous media. In particular, the mechanisms that may slow or stop coarsening have not been fully investigated. In this paper, we report an experimental study of foam coarsening in two 1-m-long and 15-cm-wide model fractures. The model fractures, Model 1 and Model 2, are made of glass plates and have different roughness. Model 1 has a regular roughness with hydraulic aperture of 46 μm. Model 2 has an irregular roughness with hydraulic aperture of 78 μm. The two model fractures are transparent, which allows direct investigation of foam in the fractures. We characterize the fracture geometries by studying the aperture distribution in the two model fractures. Both model fractures are then represented by a 2D network of pore bodies and pore throats. To study coarsening, we inject pre-generated foam at different foam qualities (ratio of gas volumetric rate to total rate) into the model fractures. After foam reaches steady-state, we shut the inlet and outlet valves of the fractures for 24 h. Foam coarsens by gas diffusion during this period. We use a high-speed camera to record images of the static foam during coarsening at two fixed locations in the fracture: 19 and 73 cm from the inlet, separately. We then use ImageJ software to process the images to study foam texture and quantify coarsening process. By correlating the aperture histogram of model fractures and water-occupied area fraction, we estimate the local aperture at water-gas interfaces at each specific coarsening time. Using the local aperture, we further estimate the height of lamellae available for gas diffusion at the end of the coarsening experiments. Based on this information, we discuss whether coarsening stops at the end of the coarsening experiments because bubbles are in equilibrium in pressure, or slows nearly to a stop because bubbles lose contact through lamellae. Coarsening studies in bulk and microfluidics assume coarsening slows and stops when lamella curvature is zero. We show in our model fractures that the lack of lamellae in wet foams can also play a part. In addition, we adopt a novel technique to calculate water saturation and capillary pressure of foam in our model fractures. We then explain how these foam properties affect its coarsening behavior.@en

Hydraulic fracturing of coalbed methane wells has been widely practised as an effective method to increase drainage efficiency in low-permeability, low-pressure and low-saturated coal seams. To investigate hydraulic fracture performance and associated seismic response in coal, hydraulic fracturing experiments were carried out on two cubic coal blocks containing a host of natural fractures using a true triaxial rock testing machine equipped with loading, injection and acoustic systems. The acoustic system uses transducers with active sources to repetitively generate and receive ultrasonic P/S wave pulses for characterising mechanical properties of the coal blocks and revealing fracture growth. Silicon oil was injected into the middle of coal blocks to create hydraulic fractures under deviatoric stress conditions, and the stress and displacement, borehole pressure and volume, and seismic response were recorded over the injection process. X-ray computed tomography (CT) was conducted before and after the experiments to identify the location and geometry of hydraulic and natural fractures. Results have shown that the fracturing behaviour, the drawdown period of borehole pressure and the intrusion of fracturing fluid are dominated by the complexity and insulation offered by internal natural fracture networks of coal blocks. In addition, seismic spectrograms captured both fracture initiation and its subsequent interaction with natural fractures, which indicates that the induced fracture and fracturing fluid interfere with the propagation of seismic waves and influence ultrasonic seismic characteristics. Seismic velocity tomography of ultrasonic acoustic signals recorded also provided the spatial information of fractures, such as approximate locations of pre-existing fractures and injection-disturbed regions.

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Gas-injection EOR processes have poor sweep efficiency due to conformance problems including channelling, gravity override and fingering. In naturally fractured reservoirs, sweep efficiency is further jeopardized, because gas breaks through fractures first, leaving most oil behind in the matrix. Strong foam can be created in fractures[1][2], thus diverting the flow of gas into matrix and hence increasing the oil recovery[3]. In the field, natural fractures are usually vertically oriented, because the least principle stress is in horizontal direction in most formations. Foam performance in fractured reservoirs is not only affected by fracture roughness, aperture, etc., but also by gravity. In this study, we investigate how gravity affect foam in fractures. To this end, we have conducted several sets of foam-scan experiments (i.e., a set of constant-total-velocity experiments each with a different gas fractional flow) on three glass model fractures (model A, model B and model C) with hydraulic aperture of 78, 99 and 128 µm respectively. The models have the same dimensions of 1 m x 0.15 m (L x W) and the same fracture roughness pattern. The transparency of glass models allows a direct investigation of foam texture inside the fracture using a high-speed camera. All experiments have been carried out at 20°C and 1 atm. Nitrogen is the gas phase, and surfactant solution is 1 wt % AOS C14-16. Experiments were carried out on all three models by placing the model either horizontally or on its side. Stable foam was created and reached local equilibrium in all horizontal-flow experiments, i.e., the rate of foam lamella creation was equal to the rate of destruction. The roughened fracture surface provided sufficient generation sites to re-create foam bubbles in sections further from the entry, hence maintaining a stable foam. In the sideways flow experiment, the effect of gravity on foam stability was not significant when fracture aperture was small (model A). As hydraulic aperture increased (model B and model C), the effect of gravity was more pronounced. Drier foam propagated along the top part of the fractures and wetter foam along the bottom. Gas saturation was 23% greater at the top than the bottom for model B, and 34% for model C. Foam was still stable during the sideways flow experiments in model B. However, foam breakage alternated with re-generation near the top in model C. We conclude that the application of foam in vertical natural fractures (meters tall and tens of meter long) with a aperture of hundreds of microns is problematic. The gravity segregation of phases for this foam would disable its capacity to divert gas flow from a tall fracture like our model into the matrix. As a result, there will be a gas-rich regime at the top of the fracture and a liquid-rich regime at the bottom. The regimes segregate more as the aperture increases. @en

A microfluidic device is one of the most stimulating research tools for foam studies, because it provides the opportunity to visualize foam behaviour directly. In this study, we employ a model similar to microfluidics, directly applicable to flow in geological fractures. The 1-meter-long model represents a fracture channel with one roughened and one smooth wall. It has a width of 15 cm and a hydraulic aperture of 128 µm. The model is made of glass plates and enables direct investigation of foam flow (Figure 1) through the channel using a high-speed camera. We conducted a series of foam experiments in the model. Local equilibrium between processes of foam creation and destruction is reached within our long model. We study the dynamics of gas trapping at different velocities and gas fractional flows. We observe that velocity affects the fraction of gas which is trapped in the model at low foam qualities. Gas trapping lessens and foam mobility increases as superficial velocity increases. This contributes to the shear-thinning mobility of the foam. At high foam qualities, the relation between trapped gas and foam mobility is weaker: gas trapping is insignificant and has little effect on foam mobility. When gas fractional flow increases at high foam qualities, flow alternates between slugs of gas and foam.@en